Haiping Lu, Johnathon Brooks, R. Legan, Steven F. Fritz
The formation of silica and silicate scales caused troublesome issues in various water-handling systems, including steam generators, geothermal wells, and waste-water disposal systems. Recently, a produced water with over 300 ppm of silica, and a spent brine off the strong acid cation (SAC) softeners containing high levels of calcium (Ca), barium (Ba), and magnesium (Mg) were commingled in the production wells. The mixing of these two waters induced silicate as well as other scales, including calcite, barite, etc. In order to provide effective scale inhibition when these waters are mixed, effective scale inhibitors for both silicate and other scales were requested for evaluation. In this paper, scale inhibitor chemistries for preventing both silica/silicate and other scales were reviewed and the possible synergistic effects were assessed by Design of Experiment (DOE) software. DOE is a systematic method to determine the relationship between several factors, i.e. various chemistries and the performance of formulations under designed application conditions. Selected chemicals were formulated for control of both silica/silicates and other scales, and their performances were evaluated by a Kinetic Turbidity Test (KTT). The KTT is a novel laboratory test method using an Ultraviolet-Visible (UV-Vis) spectrophotometer to monitor the formation of scales at various dosages of tested products. Bottle tests were also conducted for the comparison of inhibition performance. Based on the lab testing results from the KTT and the bottle tests, the combined products exhibited good scale inhibition performance for both silicate and other scales. The product was recommended for field applications. Subsequent field applications of this product have provided the desired scale control. This paper presents the laboratory testing data for scale inhibitor selection for the combination products on both silica/silicate control and other scale control by using the efficient performance evaluation method. It also provides an effective product formulation approach for finding synergetic effects of different products. Successful scale inhibitor implementations in the field applications are also presented in this paper. Both laboratory and field testing results show a good case history for the optimization of the silica/silicate and other scale treatment.
二氧化硅和硅酸盐鳞片的形成在各种水处理系统中引起了麻烦，包括蒸汽发生器、地热井和废水处理系统。最近，在生产井中混合了二氧化硅含量超过300ppm的采出水和含有高浓度钙(Ca)、钡(Ba)和镁(Mg)的强酸阳离子(SAC)软化剂的废盐水。这两种水的混合产生了硅酸盐以及其他水垢，包括方解石、重晶石等。为了在这些水混合时提供有效的阻垢剂，需要对硅酸盐和其他水垢的有效阻垢剂进行评估。本文综述了各种阻垢剂的化学性质，并利用实验设计(Design of Experiment, DOE)软件对其可能的协同效应进行了评价。DOE是在设计的应用条件下确定若干因素，即各种化学成分与配方性能之间关系的系统方法。选定的化学制剂用于控制二氧化硅/硅酸盐和其他水垢，并通过动态浊度测试(KTT)评估其性能。KTT是一种新型的实验室测试方法，使用紫外-可见(UV-Vis)分光光度计来监测不同剂量测试产品的鳞片形成。还进行了瓶试验，比较了其抑菌性能。KTT和瓶子试验的实验室测试结果表明，复合产物对硅酸盐和其他水垢均有良好的阻垢性能。该产品推荐用于现场应用。该产品的后续现场应用提供了所需的规模控制。本文介绍了采用高效性能评价方法对硅/硅酸盐防垢和其他防垢组合产品进行阻垢剂选择的实验室测试数据。为寻找不同产品的协同效应提供了有效的产品配方方法。本文还介绍了成功的阻垢剂在现场的应用。实验室和现场测试结果都显示了二氧化硅/硅酸盐和其他结垢处理优化的良好案例历史。
{"title":"Novel Laboratory Test Method and Field Applications for Silica/Silicate and Other Problematic Scale Control","authors":"Haiping Lu, Johnathon Brooks, R. Legan, Steven F. Fritz","doi":"10.2118/190705-MS","DOIUrl":"https://doi.org/10.2118/190705-MS","url":null,"abstract":"\u0000 The formation of silica and silicate scales caused troublesome issues in various water-handling systems, including steam generators, geothermal wells, and waste-water disposal systems. Recently, a produced water with over 300 ppm of silica, and a spent brine off the strong acid cation (SAC) softeners containing high levels of calcium (Ca), barium (Ba), and magnesium (Mg) were commingled in the production wells. The mixing of these two waters induced silicate as well as other scales, including calcite, barite, etc. In order to provide effective scale inhibition when these waters are mixed, effective scale inhibitors for both silicate and other scales were requested for evaluation.\u0000 In this paper, scale inhibitor chemistries for preventing both silica/silicate and other scales were reviewed and the possible synergistic effects were assessed by Design of Experiment (DOE) software. DOE is a systematic method to determine the relationship between several factors, i.e. various chemistries and the performance of formulations under designed application conditions. Selected chemicals were formulated for control of both silica/silicates and other scales, and their performances were evaluated by a Kinetic Turbidity Test (KTT). The KTT is a novel laboratory test method using an Ultraviolet-Visible (UV-Vis) spectrophotometer to monitor the formation of scales at various dosages of tested products. Bottle tests were also conducted for the comparison of inhibition performance.\u0000 Based on the lab testing results from the KTT and the bottle tests, the combined products exhibited good scale inhibition performance for both silicate and other scales. The product was recommended for field applications. Subsequent field applications of this product have provided the desired scale control.\u0000 This paper presents the laboratory testing data for scale inhibitor selection for the combination products on both silica/silicate control and other scale control by using the efficient performance evaluation method. It also provides an effective product formulation approach for finding synergetic effects of different products. Successful scale inhibitor implementations in the field applications are also presented in this paper. Both laboratory and field testing results show a good case history for the optimization of the silica/silicate and other scale treatment.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84899516","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The practice of scale squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. Many of these studies have focused on sandstone reservoir with less extensive studies carried out on carbonate substrates. This paper details work carried out using ‘squeeze life enhancer’ chemicals within the Preflush and Overflush stages utilising a co-polymer containing a quaternary amine group to evaluate this chemicals effect on phosphonate scale inhibitor retention process. Phosphonate scale inhibitors are known to provide excellent squeeze lifetimes in carbonate reservoirs due to their strong interaction with the negatively charged formation using hydrogen ion bonding at low pH or calcium ion bridging at higher pH however with the aid of an enhancer chemical it was hoped to help the retention/release process and so provide further improved squeeze lifetimes. The location of the enhancer chemical within the squeeze process was the focus of the study. Enhancing adsorption of the scale inhibitor is not objective of this application study rather ensuring that the retained chemical is released into the flowing brine during production which is a challenge in carbonate reservoirs. Laboratory work will be presented which evaluates the effect of using a polyaspartate enhancer within either the preflush or overflush stages to extend the lifetime of a commonly applied phosphonate scale inhibitor. These tests have been carried out using pack floods at 85°C with synthetic Middle East produced water and the details of the extension in treatment life observed are correlated to the inhibitor type tested and the sequence of application of the polymer enhancer utilised. The study shows how the different functional groups within the scale inhibitor interact with the carbonate mineral surface and polymer enhancer to extend treatment lifetimes and so potentially reducing the frequency of squeeze treatments and therefore total cost of operations and it is order of application of these chemicals to the rock surface that prove to be critical to the extension observed.
{"title":"Enhancing Scale Inhibitor Squeeze Retention in Carbonate Reservoirs","authors":"L. Sutherland, M. Jordan, Nalco Champion","doi":"10.2118/190715-MS","DOIUrl":"https://doi.org/10.2118/190715-MS","url":null,"abstract":"\u0000 The practice of scale squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. Many of these studies have focused on sandstone reservoir with less extensive studies carried out on carbonate substrates.\u0000 This paper details work carried out using ‘squeeze life enhancer’ chemicals within the Preflush and Overflush stages utilising a co-polymer containing a quaternary amine group to evaluate this chemicals effect on phosphonate scale inhibitor retention process. Phosphonate scale inhibitors are known to provide excellent squeeze lifetimes in carbonate reservoirs due to their strong interaction with the negatively charged formation using hydrogen ion bonding at low pH or calcium ion bridging at higher pH however with the aid of an enhancer chemical it was hoped to help the retention/release process and so provide further improved squeeze lifetimes. The location of the enhancer chemical within the squeeze process was the focus of the study. Enhancing adsorption of the scale inhibitor is not objective of this application study rather ensuring that the retained chemical is released into the flowing brine during production which is a challenge in carbonate reservoirs.\u0000 Laboratory work will be presented which evaluates the effect of using a polyaspartate enhancer within either the preflush or overflush stages to extend the lifetime of a commonly applied phosphonate scale inhibitor. These tests have been carried out using pack floods at 85°C with synthetic Middle East produced water and the details of the extension in treatment life observed are correlated to the inhibitor type tested and the sequence of application of the polymer enhancer utilised.\u0000 The study shows how the different functional groups within the scale inhibitor interact with the carbonate mineral surface and polymer enhancer to extend treatment lifetimes and so potentially reducing the frequency of squeeze treatments and therefore total cost of operations and it is order of application of these chemicals to the rock surface that prove to be critical to the extension observed.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86421897","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
G. Garcia-Olvera, O. Galicia‐López, R. Padilla-Martinez, E. Hernandez-DelAngel, A. Salazar-Munive, E. Miquilena-Rojas, M. Munozrivera, E. Santillán-Mirsaydi
In the Gulf of Mexico, an important number of wells in carbonate reservoirs produce heavy oil through electric submersible pumps (ESP). The efficiency and useful life of pumps decrease due to the formation of mineral scales inside the pumps. Study of the main scale components and their origin led to look for a scale remover that is optimal for removal and that has no detrimental effect on the ESP components. Additionally, changes in the operational procedure were implemented to decrease scale formation occurrence. Inorganic scale samples were recovered from an ESP and characterized by X-ray analysis. The scale modeling software in conjunction with water analysis provided key information to predict the scale tendency and mineral composition under reservoir and operational conditions. These analyses identified the formation of two main scale minerals: calcium carbonate (CaCO3) and calcium sulfate (CaSO4). The origin of these minerals is driven by the incompatibility of formation water with water-based drilling fluids, auto-scaling due to temperature changes occurring into the ESP equipment, and the produced water flowing through the pump. Laboratory experiments were focused on finding the appropriate scale remover that could dissolve the inorganic samples that were recovered from the ESP equipment. The screening of several products allowed identifying the chelating agent with the highest activity dissolving calcium carbonate and calcium and barium sulfate scales in a single treatment. Corrosion and sensitivity tests were carried out for the metallic and nonmetallic ESP components. These results showed that the product does not have significative effect on the different parts of the ESP equipment; compatibility tests with the heavy oil and the chelant product were also satisfactory. Because of these encouraging results, a field validation test was implemented with outstanding results—the oil well production increased significantly and the temperature in the ESP equipment was improved. The implementation of this chelating agent in wells presenting scale formation significantly improved the oil production and increased the ESP run life cycle under profitable economic indicators. The operator has implemented an operational procedure for wells operating with ESP that consists in continuous monitoring to optimize the treatments.
{"title":"A Novel Solution to Remove Carbonate and Sulfate Scale in Electric Submersible Pumps, Offshore Oil Wells in the Gulf of Mexico","authors":"G. Garcia-Olvera, O. Galicia‐López, R. Padilla-Martinez, E. Hernandez-DelAngel, A. Salazar-Munive, E. Miquilena-Rojas, M. Munozrivera, E. Santillán-Mirsaydi","doi":"10.2118/190725-MS","DOIUrl":"https://doi.org/10.2118/190725-MS","url":null,"abstract":"\u0000 In the Gulf of Mexico, an important number of wells in carbonate reservoirs produce heavy oil through electric submersible pumps (ESP). The efficiency and useful life of pumps decrease due to the formation of mineral scales inside the pumps. Study of the main scale components and their origin led to look for a scale remover that is optimal for removal and that has no detrimental effect on the ESP components. Additionally, changes in the operational procedure were implemented to decrease scale formation occurrence.\u0000 Inorganic scale samples were recovered from an ESP and characterized by X-ray analysis. The scale modeling software in conjunction with water analysis provided key information to predict the scale tendency and mineral composition under reservoir and operational conditions. These analyses identified the formation of two main scale minerals: calcium carbonate (CaCO3) and calcium sulfate (CaSO4). The origin of these minerals is driven by the incompatibility of formation water with water-based drilling fluids, auto-scaling due to temperature changes occurring into the ESP equipment, and the produced water flowing through the pump.\u0000 Laboratory experiments were focused on finding the appropriate scale remover that could dissolve the inorganic samples that were recovered from the ESP equipment. The screening of several products allowed identifying the chelating agent with the highest activity dissolving calcium carbonate and calcium and barium sulfate scales in a single treatment.\u0000 Corrosion and sensitivity tests were carried out for the metallic and nonmetallic ESP components. These results showed that the product does not have significative effect on the different parts of the ESP equipment; compatibility tests with the heavy oil and the chelant product were also satisfactory. Because of these encouraging results, a field validation test was implemented with outstanding results—the oil well production increased significantly and the temperature in the ESP equipment was improved.\u0000 The implementation of this chelating agent in wells presenting scale formation significantly improved the oil production and increased the ESP run life cycle under profitable economic indicators. The operator has implemented an operational procedure for wells operating with ESP that consists in continuous monitoring to optimize the treatments.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74520504","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
One of the biggest challenges in designing squeeze treatments is ensuring appropriate chemical placement along the completion interval. Generally, the chemical slug is bull-headed; therefore, in long horizontal wells and/or crossflow wells, exposing the chemical to all the completion intervals might be difficult. In this paper we introduce a method to evaluate placement efficiency. If placement is inadequate, some sections of the well will be unprotected, resulting in an undesirable situation: the well may appear to be protected because the inhibitor return concentrations measured at surface are above the threshold, but there is a loss of production due to scale deposition in areas of the well not contacted by chemical. In these circumstances inhibitor placement can be accurately determined by production logging, but this can be prohibitively expensive. An alternative is to use tracers to evaluate the layer flow rate distribution, and therefore quantify chemical placement. The objective of this paper is to determine if a tracer package could be deployed as part of a squeeze treatment in challenging wells, in particular in the overflush stage. If there are zones in the wellbore at different pressures, then producing the tracer back in steps at different rates will result in the tracer return concentration profile having characteristic features that can be interpreted to estimate chemical placement. Two three layer cases with crossflow are considered. In both cases, a tracer package was included in the overflush, and the resulting return profiles showed clearly the desired features. The main advantage of this approach is that there is no significant increase in the operational expense. The only additional expense will be the cost of the specific tracer and the subsequent analysis. It is envisaged that the cost is less than 5% of the total squeeze treatment cost. The results of this novel multi-rate post squeeze production stage following injection of tracer demonstrate the feasibility of including such a tracer package in a squeeze treatment. Data collected may then be used to optimise the design of subsequent treatments, to ensure that appropriate placement is achieved by rate control or by diversion, if necessary.
{"title":"Simulation of Squeeze Treatment/Tracer Programme Designs","authors":"O. Vazquez, I. Giannakouras, E. Mackay","doi":"10.2118/190752-MS","DOIUrl":"https://doi.org/10.2118/190752-MS","url":null,"abstract":"\u0000 One of the biggest challenges in designing squeeze treatments is ensuring appropriate chemical placement along the completion interval. Generally, the chemical slug is bull-headed; therefore, in long horizontal wells and/or crossflow wells, exposing the chemical to all the completion intervals might be difficult. In this paper we introduce a method to evaluate placement efficiency. If placement is inadequate, some sections of the well will be unprotected, resulting in an undesirable situation: the well may appear to be protected because the inhibitor return concentrations measured at surface are above the threshold, but there is a loss of production due to scale deposition in areas of the well not contacted by chemical. In these circumstances inhibitor placement can be accurately determined by production logging, but this can be prohibitively expensive. An alternative is to use tracers to evaluate the layer flow rate distribution, and therefore quantify chemical placement. The objective of this paper is to determine if a tracer package could be deployed as part of a squeeze treatment in challenging wells, in particular in the overflush stage. If there are zones in the wellbore at different pressures, then producing the tracer back in steps at different rates will result in the tracer return concentration profile having characteristic features that can be interpreted to estimate chemical placement.\u0000 Two three layer cases with crossflow are considered. In both cases, a tracer package was included in the overflush, and the resulting return profiles showed clearly the desired features. The main advantage of this approach is that there is no significant increase in the operational expense. The only additional expense will be the cost of the specific tracer and the subsequent analysis. It is envisaged that the cost is less than 5% of the total squeeze treatment cost. The results of this novel multi-rate post squeeze production stage following injection of tracer demonstrate the feasibility of including such a tracer package in a squeeze treatment. Data collected may then be used to optimise the design of subsequent treatments, to ensure that appropriate placement is achieved by rate control or by diversion, if necessary.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89133820","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Maciel, F. Maciel, F. Pereira, D. Ribeiro, W. Aldeia, A. Martins, M. Bloch, M. Ferreira
Scale prediction in downhole scenarios is somewhat complex due to the large range of variables that drive inorganic precipitation. While the reservoir fluid flow ascendant into the wellbore it passes through many different completion equipments such as downhole valves. In the scope of oilwell completion design, a typical wellbore configuration takes into account two or three intervals, so a selective completion is required. In this way, Sliding Sleeve Valves (SSV) are normally employed together with packers to allow the production selectivity. Despite the positive aspects of this arrangement, the turbulence, the change in the flow trajectory into the valves and the considerable pressure drop can generate a friendly environment for the occurrence of calcium carbonate (CaCO3) scale. The pressure drop in this tool induces the flash liberation of CO2 from the aqueous solution and consequently, the chemical equilibrium, which controls the precipitation of CaCO3, is displaced towards the direction of precipitation of this solid in the flowing stream. Through the computational fluid dynamics technique (CFD), this work aims to study the effect of geometric variables of a generic downhole valve and the effect of the influx flow rate and fluid properties on the minimization of the overall pressure differential in the valve. Through the discrete phase modeling (DPM), the effect of the flow intensity on the transport of the solids to the internal adhesion surfaces is verified, and which of these surfaces are more favorable to the scaling phenomenon. By comparative analysis, it is shown that the volumetric influx rate is the most significant factor in the pressure drop (response variable). For the geometric factors, the effect of the number of connections between the annular outer region and internal tube presented a greater relevance compared to the chamfer angulation effect considered at the inlet of these connections.
{"title":"Study of Carbonatic Scale in Completion Tools Through Modeling and Simulation Techniques","authors":"R. Maciel, F. Maciel, F. Pereira, D. Ribeiro, W. Aldeia, A. Martins, M. Bloch, M. Ferreira","doi":"10.2118/190703-MS","DOIUrl":"https://doi.org/10.2118/190703-MS","url":null,"abstract":"\u0000 Scale prediction in downhole scenarios is somewhat complex due to the large range of variables that drive inorganic precipitation. While the reservoir fluid flow ascendant into the wellbore it passes through many different completion equipments such as downhole valves. In the scope of oilwell completion design, a typical wellbore configuration takes into account two or three intervals, so a selective completion is required. In this way, Sliding Sleeve Valves (SSV) are normally employed together with packers to allow the production selectivity. Despite the positive aspects of this arrangement, the turbulence, the change in the flow trajectory into the valves and the considerable pressure drop can generate a friendly environment for the occurrence of calcium carbonate (CaCO3) scale. The pressure drop in this tool induces the flash liberation of CO2 from the aqueous solution and consequently, the chemical equilibrium, which controls the precipitation of CaCO3, is displaced towards the direction of precipitation of this solid in the flowing stream. Through the computational fluid dynamics technique (CFD), this work aims to study the effect of geometric variables of a generic downhole valve and the effect of the influx flow rate and fluid properties on the minimization of the overall pressure differential in the valve. Through the discrete phase modeling (DPM), the effect of the flow intensity on the transport of the solids to the internal adhesion surfaces is verified, and which of these surfaces are more favorable to the scaling phenomenon. By comparative analysis, it is shown that the volumetric influx rate is the most significant factor in the pressure drop (response variable). For the geometric factors, the effect of the number of connections between the annular outer region and internal tube presented a greater relevance compared to the chamfer angulation effect considered at the inlet of these connections.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89305274","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Baraka-Lokmane, N. Lesage, A. Fayed, M. Jungas, S. Heng, M. Jacob, P. Pedenaud
One barrel of seawater has to be injected into the reservoir in order to be able to produce the same amount of oil. In order to avoid problems of souring and/or incompatibility with reservoir water, desulphated seawater is injected. In this paper, we have completely reconsidered the desulphation process with the objective of producing more water while optimising the quantity and type of scale inhibitors, with a priority given to green chemicals. The desulphation process established since 1992 has not been modified since. Our new philosophy adapts to the constraints of the field life. Theoretical and simulations studies have been carried out on risks of scale deposition on the membrane (polarisation layer) taking into account parameters and physical laws based on fluid mechanics, electroneutrality and material transfer. The behavior of membrane and risk of deposition depends on temperature, pressure, flux, tangential flow, potential accumulation of scale on the membrane and spacer; site and laboratory pilots have been used. Tube blocking tests have been carried out in order to select the scale inhibitors. Results showed that it is possible to operate beyond 80% of recovery with the help of a scale inhibitor. 83% recovery appears to be a maximum limit. Without the use of a scale inhibitor it is possible to obtain 75% of recovery under certain circumstances. These results have enabled us to issue operational recommendations on TOTAL operating fields, on projects under development and on our future projects. The increase of the recovery and / or decrease in the concentration of scale inhibitor will conduct to less chemical discharged to the sea (via the concentrate). In addition, the selection of scale inhibitors has allowed selection of several biodegradable products, with better efficiency than currently used products. Of the 11 products tested, four have been selected. Reduction of OPEX: The consumption of scale inhibitor could be reduced by 2 or 3 and even suppressed for certain operating conditions. Selection tests have allowed us to choose most appropriate chemical from a technical, economic and environmental friendly point of view. Reduction of CAPEX: The increase of recovery has allowed us to reduce the dimensioning of the whole pretreatment of the nanofiltration as the flowrate is the parameter that influences the most the cost of a water treatment plant.
{"title":"Sea Water Desulphation – Optimisation of Scale Treatment and Reduction of OPEX & CAPEX","authors":"S. Baraka-Lokmane, N. Lesage, A. Fayed, M. Jungas, S. Heng, M. Jacob, P. Pedenaud","doi":"10.2118/190699-MS","DOIUrl":"https://doi.org/10.2118/190699-MS","url":null,"abstract":"\u0000 One barrel of seawater has to be injected into the reservoir in order to be able to produce the same amount of oil. In order to avoid problems of souring and/or incompatibility with reservoir water, desulphated seawater is injected.\u0000 In this paper, we have completely reconsidered the desulphation process with the objective of producing more water while optimising the quantity and type of scale inhibitors, with a priority given to green chemicals. The desulphation process established since 1992 has not been modified since. Our new philosophy adapts to the constraints of the field life. Theoretical and simulations studies have been carried out on risks of scale deposition on the membrane (polarisation layer) taking into account parameters and physical laws based on fluid mechanics, electroneutrality and material transfer. The behavior of membrane and risk of deposition depends on temperature, pressure, flux, tangential flow, potential accumulation of scale on the membrane and spacer; site and laboratory pilots have been used. Tube blocking tests have been carried out in order to select the scale inhibitors. Results showed that it is possible to operate beyond 80% of recovery with the help of a scale inhibitor. 83% recovery appears to be a maximum limit. Without the use of a scale inhibitor it is possible to obtain 75% of recovery under certain circumstances.\u0000 These results have enabled us to issue operational recommendations on TOTAL operating fields, on projects under development and on our future projects. The increase of the recovery and / or decrease in the concentration of scale inhibitor will conduct to less chemical discharged to the sea (via the concentrate). In addition, the selection of scale inhibitors has allowed selection of several biodegradable products, with better efficiency than currently used products. Of the 11 products tested, four have been selected. Reduction of OPEX: The consumption of scale inhibitor could be reduced by 2 or 3 and even suppressed for certain operating conditions. Selection tests have allowed us to choose most appropriate chemical from a technical, economic and environmental friendly point of view. Reduction of CAPEX: The increase of recovery has allowed us to reduce the dimensioning of the whole pretreatment of the nanofiltration as the flowrate is the parameter that influences the most the cost of a water treatment plant.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78265464","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Barium Sulphate (BaSO4) scale deposition is a serious problem encountered in oilfield operations. The precipitation of BaSO4 scale has been studied mainly for fields under water flooding. On the other hand, polymer flooding is a mature Enhanced Oil Recovery (EOR) method that has been applied successfully in many fields. This study investigates the effect of polymer flooding and salinity variations on oil Recovery Factor (RF) and on brine mixing and BaSO4 precipitation in porous media and the scale risk in producers. Reservoir simulation has been used to carry out the study. We have performed simulations using a reactive transport simulator and heterogeneous 2D areal and vertical models and a field scale 3D model. Data from literature have been utilized to define parameters that control polymer viscosity, polymer adsorption and barium (Ba2+) and sulphate (SO42-) concentrations. We have also studied the effect of injecting a low salinity water as the make-up brine for the polymer slug to see its impact on oil recovery and BaSO4 precipitation. The study shows that the injection of a viscous polymer slug reduces the mixing between injected and formation brines and so reduces the amount of BaSO4 deposition in the reservoir compared to a normal water flood. This reduction is not large and its effect on reservoir permeability is marginal. However, importantly the viscous polymer delays the breakthrough of injected water and hence the precipitation of BaSO4 at the wellbore. Including the effect of polymer adsorption makes the polymer front move slower than the SO42- front, and this accelerates BaSO4 precipitation at the wellbore and increases the total precipitation compared to the case without adsorption. A low salinity polymer slug, which contains low SO42- concentration, improves polymer viscosity, which enhances oil recovery, and reduces and delays the amount of BaSO4 deposition in the formation and in the producers. The behaviour of brine mixing is different under polymer flooding compared to normal water flooding. This work shows for the first time that this impacts the amount of BaSO4 scale that precipitates in the reservoir, and thus the timing and amount of potential scale deposition in the wellbore.
{"title":"Impact of Polymer EOR and Salinity on Barium Sulphate Scale Risk","authors":"M. M. A. Kalbani, E. Mackay, K. Sorbie, L. Nghiem","doi":"10.2118/190724-MS","DOIUrl":"https://doi.org/10.2118/190724-MS","url":null,"abstract":"\u0000 Barium Sulphate (BaSO4) scale deposition is a serious problem encountered in oilfield operations. The precipitation of BaSO4 scale has been studied mainly for fields under water flooding. On the other hand, polymer flooding is a mature Enhanced Oil Recovery (EOR) method that has been applied successfully in many fields. This study investigates the effect of polymer flooding and salinity variations on oil Recovery Factor (RF) and on brine mixing and BaSO4 precipitation in porous media and the scale risk in producers.\u0000 Reservoir simulation has been used to carry out the study. We have performed simulations using a reactive transport simulator and heterogeneous 2D areal and vertical models and a field scale 3D model. Data from literature have been utilized to define parameters that control polymer viscosity, polymer adsorption and barium (Ba2+) and sulphate (SO42-) concentrations. We have also studied the effect of injecting a low salinity water as the make-up brine for the polymer slug to see its impact on oil recovery and BaSO4 precipitation.\u0000 The study shows that the injection of a viscous polymer slug reduces the mixing between injected and formation brines and so reduces the amount of BaSO4 deposition in the reservoir compared to a normal water flood. This reduction is not large and its effect on reservoir permeability is marginal. However, importantly the viscous polymer delays the breakthrough of injected water and hence the precipitation of BaSO4 at the wellbore. Including the effect of polymer adsorption makes the polymer front move slower than the SO42- front, and this accelerates BaSO4 precipitation at the wellbore and increases the total precipitation compared to the case without adsorption. A low salinity polymer slug, which contains low SO42- concentration, improves polymer viscosity, which enhances oil recovery, and reduces and delays the amount of BaSO4 deposition in the formation and in the producers.\u0000 The behaviour of brine mixing is different under polymer flooding compared to normal water flooding. This work shows for the first time that this impacts the amount of BaSO4 scale that precipitates in the reservoir, and thus the timing and amount of potential scale deposition in the wellbore.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74608736","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised. A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods. All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells. Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "in situ" geochemical reactions between the reservoir and the injected fluid can precipitate sulphate scales. The necessity to understand these geochemical reactions and their implications for improved oil recovery and the design of smart injection brines for scale control are discussed. This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.
{"title":"Non-Chemical Methods for Downhole Control of Carbonate and Sulphate Scales - An Alternative Approach to Scale Management?","authors":"S. Heath, M. Ruslan, Eric McKay, Oleg Ishkov","doi":"10.2118/190706-MS","DOIUrl":"https://doi.org/10.2118/190706-MS","url":null,"abstract":"\u0000 The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised.\u0000 A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods.\u0000 All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells.\u0000 Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how \"in situ\" geochemical reactions between the reservoir and the injected fluid can precipitate sulphate scales. The necessity to understand these geochemical reactions and their implications for improved oil recovery and the design of smart injection brines for scale control are discussed.\u0000 This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85550504","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Xiaoguang Ma, Marte Neteland, M. Broby, J. Andreassen, M. Seiersten
Monoethylene glycol (MEG) regeneration may include a pre-treatment to reduce the concentration of cations that tend to induce scaling in the downstream process. This work reproduced pre-treatment conditions in a continuous stirred-tank reactor. The experiments were performed in 50 wt% MEG solutions at 80°C. Divalent cations and alkalinity solutions were dosed into the reactor and the mixed solution was pumped out at controlled rates. Steel rods were inserted into the test solution to measure scaling rates. The growth of scale and particles in bulk solution with varying Mg2+, Fe2+ and SO42− ions were studied as function of supersaturation with respect to calcite. The experimental results show that crystallization fouling, rather than particulate fouling, is the dominating mechanism controlling the formation of calcium carbonate scale in MEG pre-treatment. The supersaturation at steady state controlled the amount of scale. The presence of Mg2+ retarded the nucleation rate of calcium carbonate and thereby lowered the surface areas available for consumption of Ca2+ and CO32− in in the bulk solution. It resulted in higher CaCO3 supersaturation which promoted scaling. Addition of Fe2+ had little effect on scale formation. At these conditions, the calcium carbonate scale that formed on steel rods and as solids in the bulk were exclusively the aragonite polymorph. Seeding with aragonite reduced the scaling tendency in the experiments where Mg2+ was present. The result indicates that maintaining a large active surface area for growth in the bulk solution can reduce the scale formation.
{"title":"Effect of Magnesium and Ferrous Ions on CaCO3 Scaling in MEG Regeneration Pre-Treatment","authors":"Xiaoguang Ma, Marte Neteland, M. Broby, J. Andreassen, M. Seiersten","doi":"10.2118/190721-MS","DOIUrl":"https://doi.org/10.2118/190721-MS","url":null,"abstract":"\u0000 Monoethylene glycol (MEG) regeneration may include a pre-treatment to reduce the concentration of cations that tend to induce scaling in the downstream process. This work reproduced pre-treatment conditions in a continuous stirred-tank reactor. The experiments were performed in 50 wt% MEG solutions at 80°C. Divalent cations and alkalinity solutions were dosed into the reactor and the mixed solution was pumped out at controlled rates. Steel rods were inserted into the test solution to measure scaling rates. The growth of scale and particles in bulk solution with varying Mg2+, Fe2+ and SO42− ions were studied as function of supersaturation with respect to calcite.\u0000 The experimental results show that crystallization fouling, rather than particulate fouling, is the dominating mechanism controlling the formation of calcium carbonate scale in MEG pre-treatment. The supersaturation at steady state controlled the amount of scale. The presence of Mg2+ retarded the nucleation rate of calcium carbonate and thereby lowered the surface areas available for consumption of Ca2+ and CO32− in in the bulk solution. It resulted in higher CaCO3 supersaturation which promoted scaling. Addition of Fe2+ had little effect on scale formation. At these conditions, the calcium carbonate scale that formed on steel rods and as solids in the bulk were exclusively the aragonite polymorph. Seeding with aragonite reduced the scaling tendency in the experiments where Mg2+ was present. The result indicates that maintaining a large active surface area for growth in the bulk solution can reduce the scale formation.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79434246","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Produced water chemical compositional data are collected from a carbonate reservoir which had been flooded by North Seawater for more than 20 years, so there is an opportunity to analyse the large amount of produced water data collected, understand the brine/brine and brine/rock interactions and explore the impact factors behind them. In some publications, core flood experimental tests were performed with chalk cores or carbonate columns in order to make an understanding of possible chemical reactions occurring triggered by injected water with different composition (Seawater, low salinity water or any other brine). However, most of the time the laboratory conditions where core flooding experiments are implemented cannot fully simulate the real reservoir conditions. Therefore, in this study, with the help of the valuable produced water dataset and some basic reservoir properties, a one-dimensional reactive transport model is developed to identify what in situ reactions were taking place in the carbonate reservoir triggered by seawater injection. From the perspective of reservoir mineralogy, calcite, as the dominant mineral in the carbonate reservoir, is relatively more chemically reactive than quartz and feldspar which are usually found in sandstone. Whether calcite is initially and dominantly present in the carbonate reservoir rock is dissolved under seawater flooding or not is the first key issue we focused on. The effects of calcite dissolution on the sulphate scaling reactions due to incompatible brine mixing and the potential occurrence of carbonate mineral precipitation induced by calcite dissolution are investigated and discussed in detail. The comparison of simulation results from the isothermal model and the non-isothermal model show the important role of temperature during geochemical processes. The partitioning of CO2 from the hydrocarbon phase into injected brine was considered through calculation of the composition of reacted seawater equilibrated with the CO2 gas phase with fixed partial pressure (equivalent with CO2 content), then subsequently the impact of CO2 interactions on the calcite, dolomite and huntite mineral reactions are studied and explained. We also use calculation results from the model to match the observed field data to demonstrate the possibility of ion exchange occurring in the chalk reservoir.
{"title":"Reactive Transport Modelling of a Carbonate Reservoir under Seawater Injection","authors":"Yisheng Hu, E. Mackay","doi":"10.2118/190757-MS","DOIUrl":"https://doi.org/10.2118/190757-MS","url":null,"abstract":"\u0000 Produced water chemical compositional data are collected from a carbonate reservoir which had been flooded by North Seawater for more than 20 years, so there is an opportunity to analyse the large amount of produced water data collected, understand the brine/brine and brine/rock interactions and explore the impact factors behind them. In some publications, core flood experimental tests were performed with chalk cores or carbonate columns in order to make an understanding of possible chemical reactions occurring triggered by injected water with different composition (Seawater, low salinity water or any other brine). However, most of the time the laboratory conditions where core flooding experiments are implemented cannot fully simulate the real reservoir conditions. Therefore, in this study, with the help of the valuable produced water dataset and some basic reservoir properties, a one-dimensional reactive transport model is developed to identify what in situ reactions were taking place in the carbonate reservoir triggered by seawater injection.\u0000 From the perspective of reservoir mineralogy, calcite, as the dominant mineral in the carbonate reservoir, is relatively more chemically reactive than quartz and feldspar which are usually found in sandstone. Whether calcite is initially and dominantly present in the carbonate reservoir rock is dissolved under seawater flooding or not is the first key issue we focused on. The effects of calcite dissolution on the sulphate scaling reactions due to incompatible brine mixing and the potential occurrence of carbonate mineral precipitation induced by calcite dissolution are investigated and discussed in detail. The comparison of simulation results from the isothermal model and the non-isothermal model show the important role of temperature during geochemical processes. The partitioning of CO2 from the hydrocarbon phase into injected brine was considered through calculation of the composition of reacted seawater equilibrated with the CO2 gas phase with fixed partial pressure (equivalent with CO2 content), then subsequently the impact of CO2 interactions on the calcite, dolomite and huntite mineral reactions are studied and explained. We also use calculation results from the model to match the observed field data to demonstrate the possibility of ion exchange occurring in the chalk reservoir.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85144753","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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